The contents of a subterranean hydrocarbon reservoir may be estimated, for example, prior to some exploration and/or production efforts, in order to determine whether the reservoir is economically viable to produce. For example, such estimates may consider free gas, dissolved gas, and adsorbed gas. Adsorbed gas may be the gas that is located in a layer that is formed on the internal surface area of the formation matrix.
Various techniques have been developed for estimating “conventional” reservoirs (those reservoirs produced using conventional oil well methods). These techniques have been modified to apply to un-conventional reservoirs (reservoirs produced by other methods), such as shales and coals.
Reservoirs found in organic-rich shales and coals contain hydrocarbon fluids that are under a strong influence of the pore walls of the rock. This is attributed to the high surface area to volume ratio of the small pores, the fluid-pore wall interaction modulated by the wettability, and by the small pore-size distribution. The pore-size distribution of these organic shales is generally in the nanometric level (10−9 m). At the nanometric scale, pore wall interaction may provide fluid-phase transition and physicochemical properties of the fluids. The fluid-pore wall interactions may also determine the adsorption mechanism. This may result in a complex density profile of the fluid form the pore walls to the centers of the pores. The density profile may also be a function of the pressure and temperature of the system.
Experimentally The adsorption of the gas molecules in a gas shale on the pore walls may lead to unique nuclear magnetic resonance (NMR) characteristics caused by a “gas wetting” phenomenon.
Adsorption is generally considered in terms of “isotherms;” that is, the adsorption is a function of pressure at a particular temperature. Isotherm tables used in oil and gas reservoir estimation are based on the Langmuir equation. To precisely employ the Langmuir equation, a detailed isotherm analysis in the laboratory of a well core at every pressure, up to the reservoir pressure, is needed, which may be impracticable.
Furthermore, employing the Langmuir-based approach involves an iterative calculation to estimate two constants: Langmuir pressure and Langmuir volume, to create an isotherm curve for each specific sample. Such an isotherm curve represents a situation where a single adsorption layer is assumed for any porous media. Hence, it is an approximation for determining the fluid properties and the volumetric approach for calculating the reserve of organic-rich shales and coal reservoirs. Further, a Langmuir curve is measured on one sample, and the results are extrapolated to determine the volumetric calculations in the whole field.